Artificial lift system

ABSTRACT

An artificial lift system provides an artificial lift design specifically for the pumping of liquids from natural gas wells, but not limited to this application. In doing so, production rates and reserves recovered can be significantly increased. The artificial lift system uses small diameter continuous tubing to run the pump in the hole and deliver small volumes of high pressure dry gas as a power fluid to the pump. This power fluid forces liquid that has been drawn into the pump from the bottom of the wellbore to surface. By removing the liquids from the wellbore the natural gas can flow unrestricted to surface. A control system for the artificial lift system delivers a pre-determined volume of power fluid to the pump on a periodic basis. Feedback mechanisms may adjust the volume and/or the period to improve the efficiency of the pump.

BACKGROUND OF THE INVENTION

Subterranean wells have been drilled primarily to produce one or more of the following desired products for example fluids such as water, hydrocarbon liquids and hydrocarbon gas. There are other uses for wells but these are by far the most common. These desired fluids can exist in the geologic layers to depths in excess of 5,000 m below the surface and are found in geological traps called reservoirs where they may accumulate in sufficient quantities to make their recovery economically viable. Finding the location of the desirable reservoirs and drilling the wells present their own unique challenges. Once drilled, the wellbore of the well must be configured to transport safely and efficiently the desired fluid from the reservoir to surface.

Whether or not the desired fluid can reach surface without aid is a function of numerous variables, including: potential energy of the fluid in the reservoir, reservoir driver mechanisms, reservoir rock characteristics, near wellbore rock characteristics, physical properties of the desired fluid and associated fluids, depth of the reservoir, wellbore configuration, operating conditions of the surface facilities receiving fluids and the stage of the reservoirs depletion. Many wells in the early stages of their producing life are capable of producing fluids with little more than a conduit to connect the reservoir with the surface facilities, as energy from the reservoir and changing fluid characteristics can lift desired fluids to surface.

Typically fluids in a liquid phase cause the most problems when attempting to move the fluids vertically up the wellbore. Fluids in the liquid phase are much denser than fluids in a gaseous phase and therefore require greater energy to lift vertically. These fluids in the liquid phase can enter the wellbore in the liquid state as free liquids or they can enter the wellbore in the gas phase and later condense into liquid in the wellbore due to changing physical conditions. The liquids that enter the wellbore may be desirable fluids, such as hydrocarbon liquids or useable water, or they may be liquids associated with the desired fluids, for example, water produced with oil or gas. Often the liquids associated with the desired fluids must be produced in order to recover the desired fluid. Regardless of the desirability of the liquid, energy is required to transport the liquid vertically from the reservoir to surface. Optimizing the energy required through improved wellbore dynamics or with the aid of artificial lift has been an area of intense study and literature for those dealing with subsurface wells.

To improve the economics of a well, it is desirable to increase the production rate and maximize the recovery of the desired fluid from the well. Transportation of fluids from reservoir to surface, that is well bore dynamics, is one of the variables of the well that can be controlled and has a major impact on the economics of a well. One can improve the well bore dynamics by two methods—1) designing a wellbore configuration that optimizes and improves the flow characteristics of the fluid in the well bore conduit or 2) aiding in lifting the fluid to surface with artificial lift. Artificial lift can significantly improve production early in the life of many wells and is the only options for wells if they are to continue producing in the later stages of depletion. Regardless of whether the well can lift the desired fluids to surface on its own or requires artificial lift, the well bore dynamics should be reviewed continually as the variables change over the life of the well and the economics for the well need to be maximized.

The methods of improving flow characteristics include: proper tubing selection, plunger systems, addition of surface tension reducers, reduced surface pressures, downhole chokes and production intermitters. These methods do not add energy to the fluids in the well bore, and therefore are not considered artificial lift systems; however, they do optimize the use of the energy that the reservoir and fluids provide. These methods optimize the well bore dynamics and/or add energy to the fluid transportation process at the surface. Depending on the application, each of the different methods above has numerous models and configurations each having their own unique advantages and disadvantages.

With the depletion of the world gas reserves there is a need to develop an artificial lift system that is better suited to removing liquids associated with natural gas production from the wellbore. These liquids, if not removed from the wellbore, will significantly limit the natural gas production rates as wells as the ultimate recovery of the natural gas reserves.

Other artificial lift systems have been designed and used based on injection of high-pressure gas. Gas lift is a common form of artificial lift and relies on injection of enough gas to reach the critical rate for removing liquids from the wellbore (Turner et al in 1969: Turner, R. G., Hubbard, M. G., and Dukler, A. E., 1969, “Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wells,” J. Pet. Technol., 21(11), pp. 1475-1482.)

SUMMARY OF THE INVENTION

In an embodiment there is an artificial lift system, comprising a gas compressor, a gas pump seated downhole in a well and a power conduit. The power conduit extends along the well and provides a fluid connection between the gas pump and the gas compressor.

In one aspect, the invention may comprise a method of operating an artificial lift system comprising a gas pump having a pressure actuated fill valve and a bleed valve, comprising the steps of:

(a) controlling a surface fill valve to deliver a predetermined volume of power fluid at a pressure above a set point of a pressure actuated fill valve in order to pressurize a gas pump, wherein the set point of the pressure actuated fill valve is higher than the discharge pressure of the gas pump;

(b) closing a bleed valve with pressure downstream of the fill valve;

(c) opening the bleed valve by dissipating pressure in a bleed valve control line through the vent orifice; and

(d) repeating steps (a)-(c) on a periodic basis.

In another aspect, the invention comprises a control system for an artificial lift system comprising a gas pump having a surface fill valve, a pressure actuated fill valve and a bleed valve, the control system comprising a logic controller comprising:

(a) a surface fill valve controller for delivering a predetermined volume of power fluid at a pressure above a set point of a pressure actuated fill valve in order to pressurize a gas pump;

(b) a timer for actuating the surface fill valve controller on a periodic basis.

The control system may further comprise an acoustic sensor for detecting an end-of-cycle event, wherein the acoustic sensor is operatively connected to the logic controller to modify the timer period. In one embodiment, the end-of-cycle event is opening of the bleed valve.

BRIEF DESCRIPTION OF THE FIGURES

Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which:

FIG. 1 is a section view of a wellbore showing the producing formation;

FIG. 2 is a section view of an embodiment of downhole components of a wellbore showing the production formation;

FIG. 3 is a section view of an embodiment of a downhole release mechanism;

FIG. 4 is a section view of an embodiment of a downhole valve body; and

FIG. 5 is a schematic depiction of an alternative embodiment of the invention.

FIG. 6 is a graph showing pressure cycles in a typical pump cycle.

FIG. 7 is a schematic representation of a control system and method of the present invention.

DETAILED DESCRIPTION

The invention relates to an artificial lift system, and a system and method of controlling the same. When describing the present invention, all terms not defined herein have their common art-recognized meanings. To the extent that the following description is of a specific embodiment or a particular use of the invention, it is intended to be illustrative only, and not limiting of the claimed invention. The following description is intended to cover all alternatives, modifications and equivalents that are included in the spirit and scope of the invention, as defined in the appended claims.

In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present.

Co-owned U.S. Pat. No. 7,717,181, issued on May 18, 2010, describes an artificial lift system, and methods of installing and removing an artificial lift system, the contents of which are incorporated herein by reference, where permitted.

FIG. 1 is an embodiment of a wellbore showing a reservoir 15, a drilled hole from surface to the producing formation, a liquid conduit 23, including casing 10 and tubing string 9 that safely transport the producing fluids from the reservoir to surface. Also included in the drawing is the equipment associated with the pump: a downhole pump 12, small diameter continuous tubing string 8, a compressor unit 2 and a logic controller 4. The small diameter continuous tubing string 8 is also called a power conduit, a power fluid conduit or small diameter continuous tubing.

In an embodiment, an artificial lift system uses high pressure dry gas 1A as the power fluid to pump liquids from the bottom of gas wells, therefore allowing gas to flow unrestricted to surface, for example, the gas may flow to the surface unrestricted by liquid build up in the wellbore. In doing so the production rate of the gas can be increased and additional reserves recovered.

FIG. 1 shows an embodiment of the device, in which a downhole pump 12 is driven by high pressure gas from the surface. High pressure dry gas 1A is injected down a dedicated small diameter continuous tubing 8 into a pump pressure chamber 18 at the bottom of the well expelling any liquid present in the pump pressure chamber 18 through an exit check valve 19 and out of a liquid discharge port 24 at the top of the downhole pump 12. After the liquid in the pump pressure chamber 18 has been expelled, the pressure in the pump pressure chamber 18 is bled off. When depressurized, liquid from the bottom of the wellbore 17 is allowed to enter the pump pressure chamber 18 through the check valve 21 on an inlet screen 22 at the bottom of the downhole pump 12. To achieve maximum efficiency the pump pressure chamber 18 is allowed sufficient time to completely fill with liquid and to completely expel that liquid before the cycle repeats itself.

In order to recover the desired fluids from a reservoir 15, casing 10 and tubing string 9 are run in the well for the safe and efficient transportation of a desired fluid from the reservoir to the surface facilities 7 using acceptable oilfield designs. Initially, the reservoir fluids often have sufficient energy in the form of pressure to transport the desired fluids and associated fluids from the reservoir 15 to the bottom of the wellbore 17, and then from the bottom of the wellbore 17 to the surface facilities 7 without the aid of artificial lift equipment. However, once a well has reached a stage of depletion where there is insufficient energy available to transport the fluids vertically to surface the economics may justify the addition of artificial lift. Artificial lift aids in the vertical transportation of the fluids in the liquid phase from the bottom of the wellbore 17 to the surface facilities 7. Typically the fluids in the liquid and gas phases are allowed to separate in the bottom of the wellbore 17. Due to density differences, since liquids are of much higher densities, the fluids in the liquid phase drop to the bottom of the wellbore 17 where they can be pumped to surface facilities 7 up the small diameter continuous tubing annulus 23 by the artificial lift equipment. The fluids in the gas phase require much less energy to be transported vertically up the wellbore when the liquids are not interfering with this transportation. The fluids in the gas phase are allowed to flow up a tubing annulus 29 unrestricted by the fluid in the liquid phase.

For description purposes an embodiment of a downhole pump in a wellbore has been broken into three main components: surface equipment, a wellbore conduit and a downhole pump.

A compressor unit 2 comprises a gas dryer, a high pressure compressor coupled with a drive unit, an accumulator 6, a logic controller 4, a surface fill valve 3 and a surface bleed valve 5. This equipment provides a power fluid, for example a high pressure dry gas 1A, necessary to operate the downhole pump 12. The compressor unit 2 takes natural gas from the well or other desired source 1 and removes any contaminants including water. After cleaning the gas it is compressed to the desired operating pressure for the downhole pump 12 and stored in the accumulator until required to operate the pump. The operating pressure is the sum of the hydrostatic pressure of the liquid column between surface and the downhole pump 12, the pressure of the surface equipment the liquid is being discharged into, and the desired preset pump activation pressure that insures efficient operation of the pump. The accumulator 6 is connected to the small diameter continuous tubing 8, through a surface fill valve 3. Downstream of the surface fill valve 3 there is a surface bleed valve 5. These valves are controlled by the logic controller 4 which open and closes the valves for the different stages of the pumping cycle.

A power fluid conduit 8 comprising small diameter continuous tubing runs from the compressor unit 2 to the downhole pump 12. In a bleed-to-surface mode the power fluid conduit 8 delivers the power fluid 1A from the compressor unit 2 to the downhole pump 12 during the pressurization stage and from the downhole pump 12 to the surface facilities 7 during the depressurization stage. In this mode, the valve body in FIG. 4 is not installed. In a bleed-downhole mode, the power fluid conduit 8 delivers the power fluid 1A from the compressor unit 2 to the downhole pump 12 during the pressurization stage, but the surface fill valve 3 remains closed with power fluid conduit 8 pressurized to a pressure just below the downhole fill valves 201 closing set point during the depressurization stage. When running in this mode, the valve body in FIG. 4 is installed.

FIG. 2 shows an embodiment of the device in which a downhole pump 12 comprises a number of parts required for operation and serviceability of the pump. At the top of the downhole pump 12 is a connector head 30 which connects, releases and seals the power fluid conduit 8 to the downhole pump 12. Below the connector head 30 is a pump seating assembly 31 which comprises: an internal fish neck 78 (FIG. 3) for setting and retrieving the pump, the liquid discharge port 24, a NoGo ring 88 (FIG. 3) to hold the pump in position, an external seal pack 90 (FIG. 3) to isolate the liquid conduit 23 from the bottom of the wellbore 17, a connection between the connector head 30 and the pump pressure chamber 18 for the power fluid and a primary equalizing port 72 (FIG. 3) for pulling of the pump. Below the pump seating assembly 31 is a pump pressure chamber connector 32 with the connection between the pump pressure chamber 18 and the power fluid conduit 8 directly or via the downhole fill valve 100 (FIG. 4) and downhole bleed valve 28 and the connections from the liquid exit tube 26 to the liquid discharge port 24 on the pump seating assembly 31. The downhole fill valve 100 (FIG. 4) and downhole bleed valve 28 work together and as an assembly is also called a three way valve 28, 100. Below the pump pressure chamber connector 32 is the pump pressure chamber 18 which acts as a receptacle for liquids on the intake stage and a pressure chamber on the discharge stage of the pumping cycle and the liquid exit tube 26 is inside the pump pressure chamber 18 connecting an exit check valve 19 on the bottom of the liquid exit tube 26 to the liquid discharge port 24 on the pump pressure chamber connector 32. On the bottom of the downhole pump 12 is an inlet check valve 21 and an inlet screen 22.

In an embodiment, a downhole pump 12 is run in a wellbore hole on small diameter continuous tubing 8 using a conventional wireline unit having a drawworks or specially built coiled tubing unit. The downhole pump 12 has a NoGo ring 88 (FIG. 3) and an external seal pack 90 (FIG. 3) that seat in a profile 13 at the bottom of the well that is part of the existing tubing string 9. Landing the downhole pump 12 in the profile 13 holds the downhole pump 12 in place and also seals the small diameter continuous tubing 8 inside a liquid conduit 23 above the profile 13 separate from the bottom of the wellbore 17. Once in place, the small diameter continuous tubing 8 acts as the conduit to deliver high pressure dry gas 1A to the pump pressure chamber 18 and acts as a conduit to bleed off the pump pressure chamber 18 once liquids have been expelled from the pump pressure chamber 18. The annular area between the small diameter continuous tubing 8 and the existing tubing string 9 act as the liquid conduit 23 to deliver the liquid expelled from the liquid discharge port 24 to surface facilities 7. The downhole pump 12 has two check valves, one at a inlet check valve 21 where liquid from the bottom of the wellbore 17 enters the pump pressure chamber 18 and one at an exit check valve 19 where liquids are expelled from the pump pressure chamber 18 into the liquid exit tube 26 and then into the liquid conduit 23.

In an embodiment, there are three stages in a pumping cycle; the first stage starts with the pump pressure chamber 18 depressurized to a pressure below the pressure external to the intake check valve 21.

In the first stage of the pump cycle time is allowed for fluids external to the pump pressure chamber 18, for example at the bottom of the wellbore 17, to flow into the pump pressure chamber 18 through the inlet check valve 21.

In the second stage of the pump cycle time is allowed for the compressor unit 2 and accumulator to supply high pressure dry gas 1A at a sufficient pressure down the power fluid conduit 8 to the pump pressure chamber 18 to expel the liquid from the pump pressure chamber 18 through the exit check valve 19 into the liquid exit tube 26 and then out the liquid discharge port 24 into the liquid conduit 23.

In the third stage of the pump cycle time is allowed for the depressurizing of the pump pressure chamber 18 which can be done in multiple ways. Three exemplary embodiments for methods of depressurizing the pump pressure chamber are as follows:

In an embodiment of one method the gas pressure 1B is bled back to surface facilities 7 through the power fluid conduit 8 and surface bleed valve 5. This approach of bleeding off pump pressure chamber 18 and power fluid conduit 8 reduces efficiency and pump capacity but is mechanically simple and therefore is often applicable in shallower wells.

In an embodiment of a second method, a pressure activated downhole fill valve 100 (FIG. 4) and downhole bleed valve 28 are installed. These two valves 100, 28 act together as a three-way valve. This second method allows for a more efficient pump operation by only bleeding off a small amount of the gas pressure 1B from the power fluid conduit 8. When the power fluid conduit 8 is pressured up above the set point of the three way valve, the power fluid conduit 8 and the pump pressure chamber 18 are in communication and the pump pressure chamber 18 is isolated from the downhole bleed port 27 allowing pump pressure chamber 18 to be pressurized. When the power fluid conduit 8 is bled off to below the set point of the three way valve 28 & 100 (FIG. 4) the power fluid conduit 8 is isolated from the pump pressure chamber 18, at the same time the pump pressure chamber 18 and the downhole bleed port 27 are in communication allowing the pump pressure chamber 18 to be depressurized.

In one embodiment, schematically illustrated in FIG. 5, a back pressure control valve 201 and a fill check valve 203 are installed between the power fluid conduit 8 and the pressure chamber 18. The outlet of the power fluid conduit 8 into the pressure chamber 18 comprises a flow control nozzle 205 which reduces the pressure drop across valves 201 and 203. Flow control nozzle is a sacrificial nozzle which bears the brunt of the high velocity gas flow, instead of the fill check valve 203. In one embodiment, a diffuser plate 207 also diffuses the high velocity gas flow into the pressure chamber 18, reducing the jetting action of the gas, and excessive agitation of the fluid being displaced, which may result in erosion of the chamber 18 and foaming of liquid within the chamber 18. There is also the risk of gas bypassing liquid when the chamber 18 is being evacuated. The diffuser plate may be a diffusing nozzle or other means of diffusing high velocity gas flow.

Downstream from the back pressure control valve 201 is a connection to control vent orifice 211 and vent check valve 213. A vent orifice check valve 213 prevents well bore fluids from entering the control vent orifice 211.

Bleed valve 215 allows escape of the power fluid through a flow control nozzle 217. Bleed valve 215 is actuated by the pressure differential between a point upstream from the fill check valve 203 and the downhole bleed port 27. The flow control nozzle 217 transfers high velocity flow from the bleed valve 215 to the nozzle 217, thereby extending the valve life by making it less susceptible to erosion.

In an embodiment of a third method, the downhole fill valve is a back pressure control valve 201 which is installed with a downhole bleed valve 215 in similar manner as described above, acting as a 3-way valve. This third method allows for even greater efficiency in pump operation by not bleeding off a small amount of the gas pressure 1B from the power fluid conduit 8. This is achieved by setting the set point for which the back pressure valve 201 opens and closes higher then the required discharge pressure of the pump chamber. When the power fluid conduit 8 is pressured up above the set point of the back pressure valve 201, the power fluid conduit 8 and the pump pressure chamber 18 are in communication and the pump pressure chamber 18 is isolated from the downhole bleed port 27 allowing pump pressure chamber 18 to be pressurized. When the liquid in the pressure chamber has been fully discharged and the power conduit pressure will continue to drop to a pressure at which the back pressure valve 201 will close. Once the back pressure valve 201 is closed, the small volume of pressurized gas holding the bleed valve 215 in a closed position is bled off through control vent orifice 211. Once this small volume is bled off, the bleed valve 215 opens. At this time the pump pressure chamber 18 and the downhole bleed port 27 are in communication allowing the pump pressure chamber 18 to be depressurized.

A typical pump cycle comprises the three stages described above. FIG. 6 shows pressure at 5 different points in the system during an exemplary pump cycle, as well as liquid production from the pump.

Pressure in the accumulator 6 remains relatively constant (A) through the cycle, dipping only slightly at the start of the pressurization state at approximately 49 minutes. Pressure in the power fluid conduit 8 rises dramatically (B) at the start of the pressurization stage as valve 3 opens. Pressure at the pressure chamber inlet (C), upstream from back pressure control valve 201 rises somewhat as power fluid is pushed downhole, and then levels off when the back pressure control valve 201 and fill check valve 203 opens into the pressure chamber 18. At the time when the back pressure control valve 201 opens, the bleed valve 215 is actuated to the closed position. Pressure in the pressure chamber (D) rises dramatically when the back pressure control valve 201 and the fill check valve 203 opens at about 49.3 minutes. Pressure within the pressure chamber is maintained for a few minutes by flow of the power fluid, resulting in a steady increase of water production from the pump. Pump discharge pressure (E) has a baseline value resulting from the hydrostatic head of fluid in the liquid conduit 23, and increases slightly when the pressure chamber is pressurized. The discharge pressure is maintained at its slightly elevated level while the pressure chamber remains pressurized, and then returns slowly to its baseline value after the pressure chamber pressure is allowed to discharge.

In one aspect, the invention comprises a system and method of controlling an artificial lift system, such as embodiments described herein. The control system, shown schematically in FIG. 7, controls the pump cycle and each of the three stages described above.

In one embodiment, the control process consists of filling and discharging the pressure chamber with a known volume of the power fluid by controlling actuation of various valves. In one embodiment, the control process is designed to operate the system safely, reliably, and efficiently. In particular, it may be optimized to maximize production rate for a given downhole pump configuration, wellbore configuration and well production characteristic.

In one embodiment, the control system of the present invention avoids additional control lines, mechanical interfaces, mechanical switch, sensors, auxiliary equipment or components in the wellbore. The flowing and pumped fluid mediums as well as the conduits in wellbore may be used to carry control and signal from surface to pump and vice versa. In this manner, unwanted complexity, present safety concerns, added cost and potential reliability issues may be avoided.

In one embodiment, the control system comprises an acoustic system to monitor the various stages of the pump cycle. Various events in the pump cycle may produce a characteristic acoustic signal or signature, which may be used by the control system to more efficiently control the pump cycle. The produced fluid or the power fluid, or both, may be used as a medium for the acoustic signal. In addition, the acoustic signal may be used for diagnostic purposes, to determine operating integrity of pump.

The following are cycle activities to be monitored, each of which is indicative of a particular point in the cycle:

-   -   Opening of downhole fill valve 201 will provide acoustic signal         which can be identified and used for monitoring and control         purposes.     -   Opening of the bleed valve 215 will provide acoustic signal         which can be identified and used for monitoring and control         purposes.     -   Over filling pressure chamber 18 will result in gas bubbles in         pumped fluid column that will provide acoustic signal which can         be identified and used for monitoring and control purposes.     -   Venting of control vent orifice 211 will provide acoustic signal         which can be identified and used for monitoring purposes.

Another secondary function is that the flowing gas provides a medium for an acoustic signal that occurs when bleed valve 215 opens, the acoustic signal carried by this medium can be analyzed to identify reflections off of the fluid level in the wellbore which in turn can be used to determine the depth of that fluid level. This fluid level provides valuable information for determining the wells inflow performance (in combination with flowrate and pressure from M100 and P/AT 102 respectively) as well as fluid influx into wellbore required to control the pumps operating speed.

In one embodiment, the control system directly controls a surface fill valve 3 and indirectly controls the downhole valve manifold which comprises the downhole fill valve 201, and bleed valve 215. The downhole valve manifold in turn controls the downhole pumps cycle which consists of pressurizing and depressurizing the downhole pumps pressure chamber.

The primary control relies on calculations of volume of power fluid, unlike prior art systems which utilize timers, pressure monitoring or mechanical interfaces. The volume desired or necessary for pump operation in any installation may be calculated. The control system is operatively connected to an actuator (not shown) for surface fill valve 3, which is opened and closed to deliver the calculated volume of power fluid to the downhole pump for one complete cycle. In one embodiment, the volume calculated is made up of volume required to displace the chamber, volume required to account for any system losses and volume required for any overdisplacement that may be desirable to optimize pump discharge pressure (gasifying fluid discharged from pump reduces hydrostatic head and therefore discharge pressure). The actual volume delivered may be directly measured using known measurement devices. Alternatively, the actual volume may be indirectly measured by calculating the pressure loss in an accumulator using ideal gas law, and Boyle's law in particular, corrected for gas compressibility. Once the calculated pressure loss is reached, indicating the actual volume of power fluid has passed through the valve, the valve is then is shut.

As shown in FIG. 7, the logic controller 4 has data inputs which may include well parameters such as depth of the pump, properties of the produced gas, bottomhole temperature, bottomhole flowing pressure, surface temperature and wellhead flowing pressure. The data inputs may also include pump configuration parameters such as pressure chamber 18 volume, estimated or known pump cycle losses, and discharge gasification volume. An initial pump rate may also be set. The input data may be processed on an auxiliary computer, or within the logic controller itself, (step 300) and one initial result of the processing will be a volume set point (301).

In one embodiment, primary control of volume of power fluid delivered to the pump is refined with secondary control or indirect control, which is provided in part by the downhole fill valve 201. The downhole fill valve 201 is a normally closed backpressure valve that is, in one embodiment, preset for optimum efficiency before the pump is run in the hole. The design of this valve should preferably provide for the following functions:

-   -   holds backpressure on power fluid conduit to facilitate more         efficient delivery of power fluid to the pump chamber;     -   maintains backpressure above the pumps normal operating pressure         for given well conditions;     -   delivers power fluids to pump chamber when open;     -   closes the downhole bleed valve when open;     -   provides sharp opening and closing response to pressure signal         received through power fluid;     -   fully opens when set point pressure is reached delivers power         fluids to pump chamber when open;     -   provide positive shutoff of power fluid to pump chamber when         closed

Downhole fill valve 201 is not directly controlled by the control system, but rather control is achieved by delivering the volume of power fluid at a pressure higher then the backpressure set point of downhole fill valve 201. The necessary pressure may be provided by surface power fluid accumulator tanks or a compressor, or a combination of compressor and accumulator tanks. Once this pressure is reached, the downhole fill valve 100 opens (step 302) and the pressure chamber is filled (step 304) with the volume of power fluid.

Another point of secondary or indirect control is provided by the downhole bleed valve 215. The downhole bleed valve 215 is a normally-open actuated control valve that closes when the downhole fill valve 201 is open. When the downhole bleed valve 215 closes (step 306), it traps power fluid in pressure chamber when power fluid is charging pressure chamber and discharging liquid from the pressure chamber.

In one embodiment, the downhole fill valve 201 will not close until fill pressure reaches some level below its setpoint. To facilitate the proper operation of the bleed valve 28, the vent orifice and a regulating check valve 203 have been incorporated. When the desired volume has been delivered, the surface fill valve 3 will close (step 308). The pressure in power fluid conduit 8 will dissipate, and the downhole fill valve 201 closes (step (310). However, the pressure in the pressure chamber 18 is blocked by regulating check valve 203 and the pressure trapped between bleed valve 215 and check valve 203 is relieved through vent orifice 211, allowing the bleed valve 215 to return to its normally open position (step 312). Once bleed valve 215 is open, it allows power fluid in the pressure chamber to be bled off at the end of a cycle (step 314), and fresh wellbore fluids to enter pressure chamber through check valve 21. The opening of the bleed valve 215 is indicative of the end of cycle (step 312).

In one embodiment, the cycle is periodically repeated over a predetermined time interval. In the example shown in FIG. 6, a single cycle begins at about the 49 min. time mark, with opening of the surface fill valve 3. The pump pressure chamber begins to rise approximately 25 sec. later, and begins to empty out at about 51 min, 45 sec., about 2 min, 45 sec. after the surface fill valve 3 opened. The pump pressure chamber reaches its baseline level just about 3 min. after the cycle began. Some time is then allowed so that the pump pressure chamber can refill with liquid. Therefore, in one embodiment, the system may be programmed to repeat the cycle at least every 3 minutes.

In one embodiment, the control system utilizes acoustic signals and direct physical measurements feedback into the pump control program for optimization of pump rate and efficiency control.

Direct physical measurements such as pressure, temperature and flow rate may be taken with sensor devices P/AT 102 and P/AT 103 and M100. The pressures taken at P/AT 102 and P/AT 103 can be used to recalculate power fluid cycle volumes required. Gas flowrate volumes measured at M100 can be used to adjust pump rates.

In one embodiment, the primary acoustic signal which may be monitored is the signal generated by the opening of the bleed valve 215 (step 312), which is indicative of the depressurization of pump pressure chamber. The signal is best picked up from the flowing gas medium sensor P/AT 102 in the form of an acoustic/pressure pulse detected by either an increase in signal amplitude or by recognition of an identifiable signal signature (of which signal amplitude maybe a factor). The signal may also be picked up in other mediums or through conduits in the wellbore. The receipt of this signal may be used to reset the timer. If it occurs well within the original cycle length, the next cycle or a subsequent cycle may be started early, and the timed cycle may be shortened to take advantage of a higher pump rate. Alternatively, if the signal is not received, the next cycle may be delayed until the signal is received, to allow for more complete emptying of the pump chamber before the next cycle begins.

This same acoustic signal may also be analyzed to determine liquid fluid level in the wellbore. Determining where the acoustic reflection of the gas liquid interface occurs in the wellbore can be used to determine depth of the liquid interface above the pump. This form of fluid level depth identification is a standard in industry but is conventionally the result of creating a pressure pulse from surface. In the present invention, the pressure pulse is generated downhole. The pressure pulse may be created by operation of a valve in or associated with the pump, and passes to the surface, where it is reflected back downhole, and again reflected to the surface by the gas liquid interface. By feeding this signal back into the pump control, the pump rate may be adjusted as required from the determined fluid level in order to make pump system more efficient. This liquid interface can be used to calculate a flowing bottomhole pressure in conjunction with pressure data from P/AT 102 which combined with flow measurement from M101 provide valuable information regarding wells inflow performance.

Acoustic signals may in addition be captured in a service operation with accessory equipment to monitor or troubleshoot different point through out a pump cycle in order to evaluate the downhole pumps performance when problems arise. In one embodiment, specific acoustic signals that may be monitored are the opening and closing of downhole fill valve (100 or 201), venting of gas through the control vent orifice 211, opening of bleed valve 215, and gasification of liquid discharged from pump. For example, when the fill valve 201 opens one should receive acoustic signal from gas as it vents out of vent orifice and/or when it is filling the pressure chamber, thereby identifying proper operation of fill valve. Other events may produce characteristic acoustic signals which may be detected or monitored.

The acoustic signal may be detected or monitored by sensors P/AT 101 and 102, which in one embodiment are simple pressure transducers. These sensors produce signals which are input into the pump control system, and are used to suspend operation if the signal is indicative of trouble, or to otherwise modify pump operation.

In one embodiment, a leaking valve may produce an acoustic signal which is distinctive. For example, if valve 100 is leaking, the leaking gas as it vents out of vent orifice will produce an acoustic signal identifying the leak problem with valve. When the downhole fill valve 201 opens, there should be a change in acoustic signal from gas as it fills the pressure chamber, which may be indicative of the liquid level in the pressure chamber at the start of cycle. A low liquid level in the pressure chamber may be indicative of improper filling of pressure chamber due to inlet valve 21 or low fluid level in well 17.

In one embodiment, acoustic signal associated with bleed valve operation may also be used to diagnose proper operation. When the bleed valve opens, a characteristic signal from gas which is venting is produced, indicating that the bleed valve has opened and is operating properly.

Components of the control system may be described in the general context of printed circuit-board design and logic. The processing unit that executes commands and instructions may be a general purpose computer, but may utilize any of a wide variety of other technologies including a special purpose computer, a microcomputer, mini-computer, mainframe computer, programmed micro-processor, micro-controller, peripheral integrated circuit element, a CSIC (Customer Specific Integrated Circuit), ASIC (Application Specific Integrated Circuit), a logic circuit, a digital signal processor, a programmable logic device such as an FPGA (Field Programmable Gate Array), PLD (Programmable Logic Device), PLA (Programmable Logic Array), RFID processor, smart chip, or any other device or arrangement of devices that is capable of implementing the steps of the processes of the invention.

Although many other internal components of the system are not shown, those of ordinary skill in the art will appreciate that such components and the interconnections are well known. Accordingly, additional details concerning the internal construction of the system need not be disclosed in connection with the present invention. The processor may be connected to a graphical display and user input devices, which are well known in the art. The computer may comprise at least one memory, the memory containing a set of program instructions, and a processor operatively connected to the memory, the processor having components responsive to the program instructions to implement the methods described herein.

Components of the control system may be described in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc., that perform particular tasks or implement particular abstract data types.

Those skilled in the art will appreciate that the invention may be practiced with various computer system configurations, including hand-held wireless devices such as mobile phones or PDAs, multiprocessor systems, microprocessor-based or programmable consumer electronics, minicomputers, mainframe computers, and the like. The invention may also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In a distributed computing environment, program modules may be located in both local and remote computer storage media including memory storage devices.

The computer system may include a general purpose computing device in the form of a computer including a processing unit, a system memory, and a system bus that couples various system components including the system memory to the processing unit.

Computers typically include a variety of computer readable media that can form part of the system memory and be read by the processing unit. By way of example, and not limitation, computer readable media may comprise computer storage media and communication media. The system memory may include computer storage media in the form of volatile and/or nonvolatile memory such as read only memory (ROM) and random access memory (RAM). A basic input/output system (BIOS), containing the basic routines that help to transfer information between elements, such as during start-up, is typically stored in ROM. RAM typically contains data and/or program modules that are immediately accessible to and/or presently being operated on by processing unit. The data or program modules may include an operating system, application programs, other program modules, and program data.

At a minimum, the memory includes at least one set of instructions that is either permanently or temporarily stored. The processor executes the instructions that are stored in order to process data. The set of instructions may include various instructions that perform a particular task or tasks, such as those shown in the appended flowcharts. Such a set of instructions for performing a particular task may be characterized as a program, software program, software, engine, module, component, mechanism, or tool. A control system may include a plurality of software processing modules stored in a memory as described above and executed on a processor in the manner described herein. The program modules may be in the form of any suitable programming language, which is converted to machine language or object code to allow the processor or processors to read the instructions. That is, written lines of programming code or source code, in a particular programming language, may be converted to machine language using a compiler, assembler, or interpreter. The machine language may be binary coded machine instructions specific to a particular computer. Any suitable programming language or combinations of languages may be used in accordance with the various embodiments of the invention.

It should be appreciated that the processors and/or memories of the computer system need not be physically in the same location. Each of the processors and each of the memories used by the computer system may be in geographically distinct locations and be connected so as to communicate with each other in any suitable manner. Additionally, it is appreciated that each of the processor and/or memory may be composed of different physical pieces of equipment.

A user may enter commands and information into the computer through a user interface that includes input devices such as a keyboard and pointing device, commonly referred to as a mouse, trackball or touch pad. Other input devices may include a microphone, joystick, game pad, satellite dish, scanner, voice recognition device, keyboard, touch screen, toggle switch, pushbutton, or the like. These and other input devices are often connected to the processing unit through a user input interface that is coupled to the system bus, but may be connected by other interface and bus structures, such as a parallel port, game port or a universal serial bus (USB).

One or more monitors or display devices may also be connected to the system bus via an interface. In addition to display devices, computers may also include other peripheral output devices, which may be connected through an output peripheral interface. The computers implementing the invention may operate in a networked environment using logical connections to one or more remote computers, the remote computers typically including many or all of the elements described above.

Various networks may be implemented in accordance with embodiments of the invention, including a wired or wireless local area network (LAN) and a wide area network (WAN), wireless personal area network (PAN) and other types of networks. When used in a LAN networking environment, computers may be connected to the LAN through a network interface or adapter. When used in a WAN networking environment, computers typically include a modem or other communication mechanism. Modems may be internal or external, and may be connected to the system bus via the user-input interface, or other appropriate mechanism. Computers may be connected over the Internet, an Intranet, Extranet, Ethernet, or any other system that provides communications. Some suitable communications protocols may include TCP/IP, UDP, or OSI for example. For wireless communications, communications protocols may include Bluetooth, Zigbee, IrDa or other suitable protocol. Furthermore, components of the system may communicate through a combination of wired or wireless paths.

Although many other internal components of the computer or processor are not shown, those of ordinary skill in the art will appreciate that such components and the interconnections are well known. Accordingly, additional details concerning the internal construction of the computer or processor need not be disclosed in connection with the present invention.

As will be apparent to those skilled in the art, various modifications, adaptations and variations of the foregoing specific disclosure can be made without departing from the scope of the invention claimed herein. 

1. A method of operating an artificial lift system comprising a gas pump having a surface fill valve, a pressure actuated fill valve and a bleed valve comprising the steps of: (a) opening and closing the surface fill valve to deliver a predetermined volume of power fluid at a pressure above a set point of a pressure actuated fill valve in order to pressurize a gas pump, wherein the set point of the pressure actuated fill valve is higher than the discharge pressure of the gas pump; (b) closing the bleed valve with pressure downstream of the fill valve; (c) opening the bleed valve by dissipating pressure in a bleed valve control line through a vent orifice; and (d) repeating steps (a)-(c) as a pump cycle on a periodic basis.
 2. The method of claim 1 wherein the periodic basis comprises a pump cycle is initiated on a regular time interval.
 3. The method of claim 2 wherein an end-of-cycle event is used to modify the regular time interval.
 4. The method of claim 3 wherein the end-of-cycle event comprises the initiation of step (c)
 5. The method of claim 3 wherein the end-of-cycle event produces an acoustic signal which is detected by an acoustic monitor.
 6. The method of claim 4 further comprising the step of monitoring operation of the surface fill valve and/or the bleed valve by an acoustic monitor.
 7. A control system for an artificial lift system comprising a gas pump having a surface fill valve, a pressure actuated fill valve and a bleed valve, the control system comprising a logic controller comprising: (a) a surface fill valve controller for delivering a predetermined volume of power fluid at a pressure above a set point of a pressure actuated fill valve in order to pressurize a gas pump; (b) a timer for actuating the surface fill valve controller on a periodic basis.
 8. The control system of claim 7 further comprising an acoustic sensor for detecting an end-of-cycle event, said acoustic sensor operatively connected to the logic controller to modify the timer period.
 9. The control system of claim 7 wherein the end-of-cycle event is opening of the bleed valve.
 10. The control system of claim 7 further comprising a fluid level determination subsystem comprising an acoustic sensor, and wherein the logic controller comprises a module for echo determination of fluid level using an end-of-cycle acoustic event.
 11. The control system of claim 7 further comprising a diagnostic acoustic sensor for detecting valve operation events, said acoustic sensor operatively connected to the logic controller to provide valve operation status. 